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Any increase in gas production is down to the company’s development in the Arctic – not an end in itself

Any increase in gas production is down to the company’s development in the Arctic – not an end in itself
Vadim Yakovlev, Deputy Chairman of the Management Board, Deputy CEO for Upstream

— Gazprom Neft is operator on the Messoyakhaneftegaz project — a joint project with Rosneft, and Russia northernmost onshore field. You took the decision — in the face of challenging Arctic conditions — to inject associated petroleum gas (APG) from one field into strata in another. By no means a trivial move. What was the basis for that decision?

— The objective was to bring APG utilisation at the Vostochno-Messoyakshoye field up to 95%. To that end, a 47-kilometre pipeline was laid, running from Vostochno-Messoyakha to underground storage facilities located in undeveloped gas reservoirs in the neighbouring Zapadno-Messoyakhskoye field. You could say this is an unusual decision for the oil industry — it’s certainly the first time that APG from one field is being utilised in undeveloped gas strata in another.

Messoyakha is a remote field. The APG volumes produced here (about 1.5 billion cubic metres (bcm) per year) aren’t enough to support a profitable project, with gas being transported to the Unified Gas Supply System (UGSS). So it made sense to think about the reinjection option. But there’s no strata suitable for this at the Vostochno-Messoyakhskoye field. So, we took a view on the neighbouring field and, in Zapadno-Messoyakha, found an appropriate reservoir with high gas-cap tightness and considerable capacity.

Underground storage facilities are usually set up in depleted fields, where pressure has already decreased. But we are injecting gas into the original reservoir environment — which demands careful calculations in terms of engineering. We made sure to confirm our assumptions throughout the injection process.

— How are you going to address the question of the gas factor at Messoyakha, going forward? When do you plan to start feeding gas into the pipeline, ultimately?

— Pumping gas into underground storage is a reasonable solution, of itself — but it’s not a permanent one, even if we appreciate that, in 11 years’ time, we’re going to be able to recycle 1.5 bcm every year. Concurrently with all this, we’re still evaluating the adjacent resource base, and are continuing to work on generating the gas volumes necessary to justify building infrastructure to connect to the UGSS. There are several parent-company assets nearby, as well as license blocks belonging to other industry players, and licenses still in unallocated acreage. The 47-km transportation section we’ve already built is, in any case, located in the target corridor, bringing Messoyakha ever closer to existing Russian gas pipelines.

— In terms of the company’s total production, the role of Arctic projects is increasing year after year. How is this likely to increase, in the medium term? And to what extent will the role played by traditional production zones decrease?

— Production from Arctic projects will comprise about 30% of Gazprom Neft’s total portfolio within three years. Going forward, that proportion will see a consistent — and significant — increase. The Arctic — and, specifically, the Yamalo-Nenets Autonomous Okrug — is Gazprom Neft’s main source of production growth: Novy Port, Messoyakha and Prirazlomnoye will remain drivers here for a long time to come. The company is also actively involved in oil-rim development at the En-Yakhinskoye and Pestsovye fields, which are becoming new growth points in liquid hydrocarbon production.

If we’re talking about the long term, then production at new projects depends on eliminating geological uncertainties and addressing technological challenges. But we’re not placing our bets on the Arctic to the expense of other regions — we’re looking for opportunities to increase (and maintain) production profitably, everywhere.

— Could new exploration projects on the Gydan and Taymyr peninsulas be postponed due to the crisis?

— We’re still working there. Our immediate plans relate to the Leskinsky block — that is, on the Gydan Peninsula, on the left bank of the mouth of the Yenisei, where we expect to start drilling before the end of the year.

The Taymyr blocks are located on the opposite bank of the river, and the information we’re getting at Leskinsky, in terms of geology, will be important in assessing the outlook for the entire region. While we haven’t yet put any long-term plans in place for Taymyr, our immediate plans include aerial surveys and on-ground reconnaissance, and determining the necessary field work. Once the geology on the left bank of the Yenisei becomes clear, we’ll be able to think about what to do on the right bank.

— At the same time though, tenders suggest Gazprom Neft is still working on issues relating to the construction of new ports in the Arctic for hydrocarbon exports via the Northern Sear Route ...

— The priority at the moment is to choose the optimum strategy for delivering liquid hydrocarbons to target markets from Bovanenkovo and Kharasavey. A decision should be made in 2021. We’re considering three potential options: a new offshore terminal in the Gulf of Ob, or rail deliveries — either southwards on the existing Obskaya—Bovanenkovo Line, or northwards as part of building the additional Northern Latitudinal Railway-2 section.

That decision will depend on the outlook for developing Bovanenkovo and Kharasavey. The objective of pilot works currently in hand is to develop some forecasts as to the production profile: how much condensate we can expect, and what volumes of broad-fraction light hydrocarbons. We’ll then be able to understand the economics of these three options, and choose the best one. If the decision is taken to create a new liquid-hydrocarbon shipping channel in Yamal then this infrastructure could be used for the entire region’s resource base.

As regards other transport facilities that could be located in the waters of the Yamalo-Nenets Autonomous Okrug or in the Krasnoyarsky Krai — these decisions will depend on the outcomes of pre-development activities. There are reserves in Yamburg, but questions arise over selecting technologies, and the economics of development. In terms of the mouth of the Enisei River, we first need to get an idea as to reserves: and that’s not going to happen any time soon.

— Gazprom Neft is increasingly talking about gas. The company is gradually changing from an oil to an oil-and-gas company. To what extent is gas’s role in production going to increase?

— Any growth in the gas component has never been a goal in itself, for us. The fact that this is happening now is the result of company’s ongoing development in the Arctic. This is the inevitable result of changes in reserves initially in place (RIIP), and the greater importance of the gas factor at oil fields. In addition to which, we often find that infrastructure solutions become more effective when planned for in the context of treating and transporting all kinds of hydrocarbons.

At the same time we are, naturally, expanding our expertise in working with multi-component reserves. For instance, we have, for some time, been developing gas-condensate deposits through a joint venture with Novatek-Arcticgas, and have now acquired similar assets from our parent company — by which I mean the Bovanenkovo and Kharasavey projects. That said, all decisions will be made in close cooperation with Gazprom, and as part of putting a long-term gas balance in place.

The role of gas in Gazprom Neft’s total production will certainly continue to grow. Total investment in gas projects will be about 30% over the next three years. With the launch of new projects — at Urengoy Achimovsky strata, as well as Bovanenkovo and Kharasavey — between 2024 and 2026, the role played by gas in total production will increase to 45%.

We are developing in line with the general mindset in the fuel and energy sector, where the gas component is starting to hold sway in new projects. And this is making Gazprom Neft more resilient in the light of the current situation on the oil market: under the OPEC+ deal companies have to reduce oil production, so increasing gas production presents an additional opportunity for us to expand the size and scale of our business.

— The key project right now is Yamal Gas. How’s that going?

— Literally — at full tilt. We are building heavy-duty gas infrastructure, which will underpin the economically viable and fully integrated development of hydrocarbon reserves in the south of Yamal. Two key facilities are currently under construction — the export gas pipeline through the Gulf of Ob, and expanded facilities at the Novoportovskoye gas processing plant (GPP).

The Yamal Gas project team delivered ahead of plan during the winter season, with more than 36 kilometres of the 56-km onshore pipeline being laid, and onshore facilities constructed. The laying of the gas pipeline from the Yamal Peninsula through the Gulf of Ob started in early July. These are major, large-scale works, which will involve the deployment of a total 55 vessels, offshore. We are now starting work on laying the pipeline from the Tazovsky peninsula. We plan to complete the laying of the pipeline along the Gulf of Ob seabed over the summer and into autumn, up to October, and will finish onshore operations next winter, where two-thirds of the plan is already complete. Concurrently with this we will also be laying a gas pipeline to the village of Novy Port, so that we can supply gas to that settlement.

Active construction is also now underway at the Novoportovskoye GPP-expansion site. Piles to support production equipment and overhead racks have been positioned and sunk during the winter. Reinforced concrete foundations have been poured for booster-compressor-station (BCS) and gas-pumping-unit (GPU) equipment— under very challenging climatic conditions. Work is now ongoing on installing metal structures to support GPU feedstock racks, and to feed gas into the gas export pipeline.

We expect to begin start-up and commissioning activities at the expanded GPP in mid-2021, and will be ready to start feeding gas into the UGSS by 2022. By which time we expect to have increased GPP capacity to 17.5 bcm per year.

Implementing the Yamal Gas project has coincided with the pandemic, but we are following all quarantine measures, to the letter. We’re trying to move over to handling as many operations as possible remotely, particularly in the most important areas, and are continuously COVID-testing all personnel and contractors’ employees.

— And how promising does the company expect gas—chemical projects in the Arctic to be for Gazprom Neft?

— You have to think about the target base for the gas and chemicals industry as early as the reserves-preparation stage — when projects are being put in place with a view to finding the most efficient ways of monetising resources. In terms of reserves, the changing role played by gas is creating a potential resource base and the preconditions for implementing gas-and-chemicals projects. There are, also, certain regional issues — there is more wet natural gas than dry gas in the north of Yamal. There are millions of tonnes of ethane, propane and butane, all of which have traditionally been used as feedstocks for the gas-and-chemicals industry. Yamal’s reserves are huge and, in terms of volumes of raw materials, are comparable those needed by Western Siberia’s entire gas and chemicals industry. Added to which, these are world-class resources in terms of scale and quality: and gas-and-chemicals markets are growing faster than oil and gas markets.

On that basis then, it’s clear to us all that these resources should, at the very least, be analysed and investigated. We’re doing that, doing our own assessments and consulting with companies specialising in this area. We need to establish industry-focussed dialogue with all stakeholders and interested parties so that a solution develops that will prove a driver in developing not just our own but related industries too, making it possible to monetise new reserves as effectively as possible.

— Going further into the Arctic then — the extended continental shelf. Gazprom Neft has stated that it is reviewing the pace and timing of its offshore projects — due to macroeconomic factors. Has the company asked the Ministry of Natural Resources to postpone lead-times and deadlines regarding work on offshore projects?

— We have, already, undertaken a very large amount of work at our license blocks, ahead of schedule: about 20,000 metres of 2D seismic and 7,000 km2 of 3D seismic — as well as drilling three wells offshore in the Sea of Okhotsk over the last three years.

A large volume of geological information has been collected, as a result, which now needs to be carefully analysed. And the current market environment means we can take our time — particularly since we’re only due to drill our next well, at the Dolginskoye field, in 2023.

On which basis, we have fulfilled all licensing obligations and can move ahead with desk work to put solid foundations in place for launching these projects, at our own pace.

 Gazprom Neft’s most promising offshore exploration projects — the Neptune and Triton fields — are in Sakhalin. With the unfolding crisis, will you be forgetting about any potential partnerships at these assets?

— Absolutely not. We’ve done a considerable amount of geological exploration on the Sakhalin continental shelf. Apart from which, the Sea of Okhotsk continental shelf having been deemed to have a Category 4 level of complexity has improved the economics on these projects.

The most important thing is that we have started evaluating options in terms of surface-infrastructure development. We think that using existing Sakhalin-2 infrastructure could prove optimal, particularly given the position of our parent company. That sort of configuration would be the basis for any decision on developing this asset. But projects on this sort of scale really need to be developed in conjunction with partners. So it’s going to be a two-stage process: first we have to agree on infrastructure — and that conversation has already started — and then we’ll move on to putting a putting a partnership structure in place.

— Are you still in talks with Shell about joining the Sakhalin projects?

— That conversation is still ongoing — with Shell and other potential partners.

— What stage are you at in forming a joint venture with Novatek in the Arctic — the first asset of which, we understand, is going to be the Severo-Vrangelevsky block, offshore in the Chukchi Sea?

— We are in the process of preparing legally binding documentation. We plan to incorporate the joint venture in early 2021. All agreements are in place, and we are progressing in line with our collective plans.

 Gazprom Neft’s major new assets in recent years have been projects transferred from Gazprom under long-term risk-operatorship agreements. Are we going to see Gazprom Neft getting more of these agreements on Gazprom fields?

— These represent a universal mechanism for structuring relationships between Gazprom and Gazprom Neft. They’re also appropriate for work at other blocks, but we have enough assets in our portfolio at the moment. We’ve acquired a significant additional investment burden under these long-term risk-operatorship agreements — we’re bearing some considerable responsibility to our parent company. So, for now, we’re focussing on making sure we fulfil all of the commitments we’ve made, to the letter. Of course, we’re constantly updating our strategy, and looking for new sources for growth, but the priority is implementing those projects we’ve already started.

 How has the “new normal” under COVID-19, and the drop in oil prices, impacted the management of the company — and management’s performance?

— Right now, what we can say for sure is: it wasn’t so much that the crisis and coronavirus pushed Gazprom Neft to any one decision or another, but rather that the “new normal” prompted the company to adopt management processes it had previously decided upon. Which included moving further towards complete transformation — in developing integrated business processes, and in implementing digital solutions. Our employees are, increasingly, working in cross-functional teams, developing new products and supporting these throughout their entire lifecycle — from original idea to full-scale rollout. And what’s happening now in terms of company management is very different from traditional models built around the principle of hierarchical, top-down engagement.

We’re teaching our senior management to work in a new way: we’re putting in place a distributed system for knowledge management, and platforms to allow collaborative work, remotely.

Working in cross-functional teams is both a risk, and an opportunity. We never know in advance which ideas are going to take off and find their feet, and which aren’t going to pay off. But — in doing this — we’re building an internal “initiative” culture. A kind of motivational system aimed at making sure employees are ready to seek out new opportunities for improvement, initiate projects, and get stuck in to working on them. The senior management team doesn’t make any claim to taking the final decision on every issue. This kind of “distributed” model — in terms of responsibility and business structuring — creates the preconditions for an ongoing, dynamic, self-fulfilling work process. This is particularly important for a company whose assets are distributed across a wide area, geographically, and which require completely different products and solutions.

 Is this similar to the management system adopted at major IT companies?

— Probably. The key feature of IT companies, in fact, is that they are constantly creating new solutions. And there’s certainly a degree of similarity here. We also know how to experiment, and take calculated risks; and we know how to launch new projects while working with high levels of uncertainty. After all, once geological prospecting starts, industry averages suggest the odds on achieving success are about 20–30%. So the “Fail Fast” principle — which is aimed at eliminating all non-viable options as quickly as possible, in the earliest stages — is also widely used in the oil industry. As in IT companies: test hypotheses fast; reject inefficient options; and concentrate on the most promising ones. When embarking on geological prospecting the first thing we do is set ourselves the task of determining precisely what research or investigations, specifically, will give us the most essential information, and narrow scope for uncertainty. In other words — we look at various options, and find the best one. In terms of action logic, this is similar to what a company developing digital products does.

 Oil production has been cut back as a result of the OPEC+ deal — probably for some time. So there’s not going to be any need for the same number of employees as when production was going up. Will this change in production levels impact the number of employees at Gazprom Neft?

— We’re not planning any moves in terms of mass layoffs or making people part-time. But, at the same time, employee productivity — as a performance metric — is important to us: it’s something we manage and monitor. The way we structure our work is based around this. Yes, we have freed up some of our workforce due do the cut in production levels: we’re thinking about how to redeploy them. We’ve cut back on external recruitment, as a priority, and are trying to fill all vacancies internally. Specifically — we are moving employees between businesses, transferring them to developing assets and promising projects. We’re now deploying in-house staff to undertake some of the services previously provided by outside organisations: and, of course, we can always reassign them.

 One sore point for the domestic oil industry remains the introduction of the excess profits tax. The Ministry of Finance has talked about budgetary shortfalls in the hundreds of billions of rubles, and is seriously questioning the need to expand pilot EPT projects to new fields. Have oil companies managed to defend their position on the need to continue this experiment?

— This is, without a doubt, a very important issue for the entire oil industry, and one that requires consistency and accuracy in dealing with it. It’s important to understand that we are working together, to the same end: creating added value — for the country, and for the industry.

In trying to find a solution to a complex problem, you generally need to ask three questions, one by one: ‘why’, ‘what’, and ‘how’?

The first question is — why did we turn to the EPT? And the answer is: to harmonise the tax system — which, as we all know, is, due to the constant appearance of one specific solution or another, becoming ever more complex, unwieldly and erratic. Why is this? Because the underlying tax system was developed quite a long time ago, and remains somewhat crude. It does not, in particular, take production environments under different geographic, geological and climatic conditions into account.

The answer to the question “What needs to happen in order to create a harmonious system” is simple — introduce the EPT. No one is putting forward any realistic alternatives to that system, after all. So, we have to mould this mechanism, one way or another, and fine-tune it — that is, try and answer the third question: how?

We need to appreciate that we’re at the pilot stage. This experiment is being undertaken at assets accounting for just 10% of the country’s oil production. The Ministry of Energy has, already, assessed the initial results of the industry’s operations under the EPT quite favourably. The objectives in any pilot project are to confirm hypotheses, eliminate uncertainty, and help fine-tune the relevant mechanism.

This pilot project has, among other things, identified which issues are definitely going to need further attention. It has demonstrated that the EPT needs to be customised across a broad price range. We are all seeing just how dramatic market changes can be across a three- to four-year term. The second crucial element is the relationship between various elements — such as rent and profit taxation — under the new tax regime.

Since we’re now at the point of testing the new system, we need a calm and balanced expert assessment of the results, and solutions on how to improve this mechanism. The criteria for this, of course, need further discussion. Because calculations are, at the moment, being undertaken on a fairly linear basis: tax revenues are taken on a ‘before’ and ‘after’ basis, but production levels — by default, are assumed to be constant. This is incorrect. If we could get this oil under the normal tax regime, then we wouldn’t need to change anything. But we are, together with the government, moving towards changing the system precisely in order to create incentives for obtaining additional oil that simply wouldn’t be produced otherwise — meaning there simply wouldn’t be anything to tax.

Added to which, any assessments need to be made not just on the basis of looking back over a very short period (of one to two years), but taking longer periods into account. After all, you have the investment stage, and then the point at which you start receiving an income. We need to look at all sources of income, not just the EPT and the mineral extraction tax (MET). There’s also the profits tax, and dividends from state-owned companies. So, that way, we can make a comprehensive assessment.

Our job is to prove the effectiveness of this system, for everyone — companies and state alike. So, I’d like to stress, again, that we don’t see any alternative to the EPT, one way or the other. The results obtained need to be analysed properly, fully comprehended, and turned into further fine-tuning of the mechanism. And it is, now, very important that we join forces and move forwards in order to create some added value — in new additional oil and new extra revenues for the country.

 And a few questions on the subject of OPEC+. Do you agree with the assertion that there will be a shortfall on the oil market in July?

— There is a certain lag between what’s actually happening in the market and objective information on indications such as the supply—demand balance and stock volumes. There is a view that the market reached a balancing point as early as June. We don’t see this as yet from the indicators mentioned above. But those factors that impact the state of the markets do, in general, confirm that trend.

All parties to the deal are fulfilling their obligations in a disciplined manner. Production in North America has declined, and we don’t yet see any signs of recovery. The depth of the market slump, and reserves stocks, weren’t, ultimately, as dramatic as was made out in the most alarming forecasts. We are seeing steady demand for Russian oil and, even, a deficit — reflected, among other things, in price quotations, in premiums on Urals crude relative to other blends.

Indicators do indeed show that the market has stabilised. The assumptions factored into designing the OPEC+ deal are, generally, proving to be justified. It’s possible the situation could prove still more optimistic. Obviously, there are some uncertainties as to a possible second wave of the pandemic. But, either way, neither we nor the experts expect that the depth of any correction under such a second wave — if it happens — will be as deep as in the first stage. Right now we’re seeing a recovery, and expect this to continue.

 OPEC+ countries will start increasing oil production in August. Has the Ministry of Energy discussed this with Russian oil companies yet?

— We are in regular consultations, and there’s always some ongoing reconciliation of views: we have a longstanding working relationship. Increasing production won’t require any special radical solution — everything will pan out as part of previously agreed plans. There are certain quantitative parameters we expect to reach in August, and we are intent on using this opportunity.

— How sustainable do you think the current $40-a-barrel oil price is, and what’s your forecast to the end of the year?

— We think today’s price reflects the current state of the market. We prefer not to make forecasts and, in any case, we don’t try to guess any price level. The company produces multi-scenario forecasts for its own use, and prepares its plan of action within a certain pricing horizon. There’s not, at the moment, any real reason to suppose that current price levels could change much.

 Gazprom Neft CEO Alexander Dyukov has, previously, suggested moving from focussing on reserves inventories to focussing on OPEC+ market share. How might this work in an environment that has different producers, with different cost levels and different financial capabilities? Might we — and other OPEC+ countries — end up giving up our competitive advantage?

— The point here is the parties to the OPEC+ deal being able to target their share against a background of increasing global demand for oil.

If we’re talking about long-term trends — we expect demand to grow. And the parties to the OPEC+ deal need to think about what a fair share of that growth might be, for the OPEC+ signatories. This means you can manage capacity planning, and take a view on long-term projects and investment programmes.

This idea is finding some sympathy in industry discussions. But, of course, what everyone’s concerned about at the moment is how the short-term situation is going to pan out. I think it will be appropriate to return to the issue of focussing on OPEC+ market share a bit later on. That mechanism needs to have two elements: the ability to achieve short-term market stabilisation, if necessary, and the ability to deliver a fair share for OPEC+ participants, in the long term.